System to enable geothermal field interaction with existing hvac systems, method to enable geothermal field interaction with existing hvac system

ABSTRACT

A system for adapting an HVAC system in an existing building for utilizing geothermal energy is described. The system uses an incoming flux of geothermal energy, along with a plurality of heat exchange surfaces adapted to receive the incoming flux of geothermal energy. The system also includes an interface between the HVAC system and the heat exchange surfaces. The interface is adapted to transfer the geothermal energy to the system. A multiplier sub for a drill rig and several drilling assemblies are also described, along with a system to reduce vibration.

PRIORITY

This application claims the benefits of U.S. Utility application Ser.No. 12/645,741 filed on Dec. 23, 2009, presently pending, which in turnclaimed priority to U.S. Provisional Application Nos. 61/270,851, filedon Jul. 14, 2009, presently expired, both applications herebyincorporated by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to a system and a method to enable widespreadadoption of geothermal energy and more particularly this inventionrelates to a system and a method for facilitating energy transfer from ageothermal field to an existing HVAC system of a building with minimalretrofit, thereby enhancing or retro fitting existing conventional HVACsystems with minimal interference of daily activity within the building.

2. Background of the Invention

Geothermal energy is an alternative energy source existing under ground.The goal for geothermal energy use is to utilize the typical midrangeconstant temperatures of 52 to 54° F. found beneath the earth's surfaceto help heat or cool a structure in winter or summer, respectively.

Conventional geothermal well fields are drilled with wells havinguniform depths and approximately 4-6 inch diameters. Field depth mayvary from 75 feet (or less) to 600 feet (or more). After each well isdrilled, a high density geothermal loop is then inserted to the bottomof each well.

Once the loop is in place within the well, the well is pressure-grouted,starting from the bottom of the well up to its opening at the surface ofthe earth. The grouting both improves thermal conductivity of the loopwith the surrounding formation, and seals the well bore to preventcontamination of the surrounding geological features.

Efficiency dictates that thermal conduction of underground temperaturesto the thermal conduction fluid loop be maximized. As such, the diameter(referred to as the “caliper”) of the wells must be strictly controlledso that cavitating (also known as washout) of the well bore does notoccur. Washout of the well bore caliper, or an unnecessary increase inthe diameter of the well bore, results in a loss of the loop's abilityto transfer a considerable percentage of energy. Large voids or largecaliper well bores require much more annular space to be filled betweenthe loop and the bore hole wall with grout material. This results in aloss of thermal conductance from the earth to the loop at that point.

Air Hammer Drilling

A myriad of drilling techniques are available for geothermal wellproduction, including air hammer drilling (which is typically utilizedin consolidated, e.g. Bed Rock formations), and circulating muddrilling, (which is utilized in glacial drift or overburden e.g.,gravel, sand, and clay).

Air hammer drilling utilizes a rotary bit that slams against, thenremoves bits of, the consolidated formation being drilled. Air rotarydrilling methods are almost exclusively utilized in hard consolidatedformations to speed up and cut costs of drilling in bedrock. Aircompressors are utilized to force air down the drill pipe through a downhole air hammer on the bottom end of the drill string. Exhaust air fromthe hammer evacuates the area between the drill string and the wall ofthe bore hole thereby lifting large volumes of water and mud out of thebore hole.

Air rotary drilling cuts through dense structures (i.e. bedrock layers)quickly, and, compared to circulating mud drilling, it is particularlyuseful when lost circulation occurs. This is because the air used in airrotary drilling technique tends to lift water, which seeps into the wellbore (from fissures, aquifers and other voids).

Environmental containment of the drill site with air rotary drilling isvery challenging. Fuel consumption of equipment utilizing this method isextremely high due to massive amounts of horse power spent producinghuge amounts of air at extremely high pressures. A 6 inch diameter borehole at five hundred ft in depth requires constant generation of up to1000 CFM (cubic feet per minute) at 350 psi (pounds per square inch).This is twice the horse power required by mud rotary systems to drill atthe same depth.

Other drawbacks to air rotary drilling include disruption of adjacentstructures such as aquifers and nearby wells. As such, air hammerdrilling is best utilized when wells are spaced at least 150 feet fromeach other.

Mud Rotary Drilling

Mud rotary drilling uses mud to carry away cuttings. FIG. 2A is aschematic of a standard drill-string 12 with mud rotary drilling in use.The down-pointing and up-pointing arrows show the direction of drillingmud, which is initially injected at the top center of the drill string.The drilling mud is pumped through the center of the drill string andout of the rotary bit 14. With continued pumping, the mud is pushed tothe surface of the well bore, taking with it the bore cuttings entrainedin the mud. Thus, the mud serves as a vehicle to remove bore cuttings asthey are produced.

Mud rotary drilling is less disruptive to nearby geologic structures,but also less effective in penetrating dense structures even whenexpensive diamond bits (such as those featuring polycrystalline diamondcompact (PDC) inserts) are used.

Also, mud rotary drilling stops working when large cavities develop orare encountered during drilling, inasmuch as mud pressure dropssignificantly in these scenarios. A subsequent drop in the return mudvolume through the annulus (i.e., the space between the drill string andthe sides of the well bore) results in cuttings not being carried to thesurface of the hole for evacuation. This reduction of flow may generallybe classified as seepage (less than 20 bbl/hr [3 m3/hr]), partial lostreturns (greater than 20 bbl/hr [3 m3/hr] but still some returns), andtotal lost returns (where no fluid comes out of the annulus). In thissevere latter case, the hole may not remain full of fluid even if thepumps are turned off. If the hole does not remain full of fluid, thevertical height of the fluid column is reduced and the pressure exertedon the open formations is reduced. This in turn can result in anotherzone flowing into the wellbore and a catastrophic loss of well control.

Contained mud rotary systems provide a reserve capacity for generatingmore mud. But, such systems usually cannot generate enough mud toovercome the aforementioned pressure and/or volume drop when largecavities are encountered in consolidated formations. At that point, themud rotary drilling is finished, and other drilling methods must beapplied.

In light of the foregoing, state of the art geothermal field developmentrelegates the use of geothermal energy to venues able to accommodatelarge silt ponds, high volume water run off, and substantial scarring ofthe landscape associated with air hammer drilling. As such, largecampuses, outlying industrial sites, or abandoned brown fieldsheretofore were the only candidates for geothermal well development.

Current industry standards set by The International Ground Source HeatPump Association (IGSHPA) specifies grid pattern spacing of 10 ft to 20ft between wells. Often, geothermal wells are 150 ft to 200 ft in depthdepending on the relationship and distance from the equator. Each ofthese wells yield approximately one ton or 12,000 BTU of geothermalenergy. Most single family homes are approximately 2000 square feet ofliving space. Modern built homes require from 3 to 4 ton of geothermalenergy to supply heat pump load requirements. Three to four wells spaced20 feet apartment usually can be accomplished in most rural back yards;however the much larger tonnage requirements of high rise buildings andcommercial businesses make the possibility of installing geothermal wellfields on sidewalks, alley ways, and parking lots a real challenge.Given that most commercial loads are a minimum of 20 to 30 tons, andtherefore require a minimum of 20-30 wells, such a geothermal well fieldtypically requires 200 to 300 foot blocks of space.

Drilling deeper wells has not been an attractive option for multiplereasons:

1. The geothermal well drilling industry has no method for assuring aconsistent caliper for wells at any depth.

2. Deep well drilling results in massive amounts of water and drillingspoils (cuttings) generated during air rotary drilling. This raisesenvironmental issues.

3. Lack of a method for competitively using mud rotary drilling inconsolidated formations. Loss of mud circulation becomes particularlyacute in deep drilling. State of the art mud rotary drilling methods arenot effective after lost circulation zones are encountered; thereforecasings must be set deep through the zone. This casing installation isneither cost effective nor easy to remove.

4. Deterioration of silica sand-based grout during air rotary drillingin deep consolidated formations. This leads to contamination of freshwater aquifers.

A need exists in the art for a system and a method for applyinggeothermal energy to footprints not exceeding a standard city lot. Thesystem and method should accommodate field development on the city lotalready containing a house, an ongoing commercial enterprise, or otherpermanent structure. The system and method should also obviate the needfor completely retrofitting the HVAC of the permanent structure toutilize the geothermal energy. The method should also optimize state ofthe art mud rotary drilling techniques for their use in lost circulationzones.

SUMMARY OF INVENTION

An object of the invention is to provide a system and a method forutilizing geothermal energy that overcomes many of the disadvantages ofthe prior art.

Another object of the invention is to provide a system for utilizinggeothermal energy extracted from a city-lot to supplement energy needsof permanent structures on the city lot. A feature of the invention is ameans for utilizing existing HVAC systems of the structures to providegeothermal energy to the structures. An advantage of the invention is nodisruption of activity within the structure during the establishment ofthe geothermal field, or hook up of the field to the HVAC system.

Yet another object of the present invention is to provide a method forestablishing 4 to 5 tons of geothermal energy from one well, making a30-60 ton geothermal field on 2000 square feet of real estate apossibility. A feature of the invention is enabling the drilling of aplurality of wells in close spatial relationship to each other, eachwell of which is approximately 300 to 700 feet deep. An advantage of theinvention is that the increased depth, and therefore capacity, of eachwell results in a geothermal well field with a smaller foot print. Thisprovides a means for harvesting geothermal energy from within denselypacked, urban areas.

Still another object of the present invention is to provide a system forproducing geothermal well fields in any formation. A feature of theinvention is the primary use of rotary drilling to backfill and minimizefractures in the walls of the well bores. An advantage of the system isthe minimization of environmental impact on ground surfaces, and aconcomitant tight packing of geothermal wells within smaller groundfootprints.

Another object of the present invention is to provide a method forproducing a tightly packed well field in any geologic formation. Afeature of the method is manipulation of a reverse auger in wells torepair fractures along bore walls, whereby the manipulation includesrotation of the auger, and lifting of the auger, all at speedsultimately detrimental to above-hole equipment. An advantage of theinvented method is that it allows for the establishment of working wellswithin a few feet of each other.

Briefly, the invention provides a system for charging an HVAC system ofan existing building with geothermal energy, the system comprising anincoming flux of geothermal energy; a plurality of heat exchangesurfaces adapted to receive the incoming flux of geothermal energy; andan interface between the HVAC system and the heat exchange surfaces,said interface adapted to transfer the geothermal energy to the system.

Also provided is a method for repairing aberrations along a drill borewall, such aberrations including lost circulation zones (LCZ) ingeothermal well bores, the method comprising using a rotary mud drillsystem to produce a drill hole, wherein the system employs a firstreturn mud pressure value; removing the rotary mud drill when return mudpressure decreases to a second return mud pressure value; inserting areverse auger 22 (i.e., in the case of a right-handed drillingoperation, the auger 22 defines left handed flighting) into the drillhole to the point where the return mud pressure decreased to the secondpressure value; actuating the auger; introducing loose substrate, (i.e.lost circulation material (LCM)) such as bentonite, into the drill hole;allowing the substrate to contact the auger 22; and lifting and loweringthe auger along longitudinally extending regions of the drill holedefining the point P where the return mud pressure decreased to thepredetermined value for a time and in substrate amounts sufficient tocompress the substrate into that portion of the bore wall defining thelost circulation zone.

Also provided is a system for minimizing vibration of drilling equipmentduring production of oil, gas and geothermal well bores, the systemcomprising a multiplier sub for a drill rig having an above ground drivemotor to form an elongated hole by dislocating solid material of theearth, the multiplier sub comprising a sleeve having a threaded maleconnector attached to a sleeve tube, where the sleeve tube includes ansleeve tube interior surface lined with teeth; a mandrel having athreaded female connector attached to a mandrel shaft, where the mandrelshaft is positioned within the sleeve tube and includes a mandrel shaftexterior surface lined with teeth; a first gear cluster having aplurality of first gear cluster pin gears positioned within the sleevetube between teeth of the sleeve and mandrel; and a second gear clusterhaving a plurality of second gear cluster pin gears positioned withinthe sleeve tube between teeth of the sleeve and mandrel, where the firstgear cluster is separated from the second gear cluster by anintermediate bearing, and where a teeth ratio between the sleeve themandrel, the first gear cluster, and the second gear cluster is a valuethat configures the mandrel to spin at least twice as fast as thesleeve.

BRIEF DESCRIPTION OF DRAWING

The invention together with the above and other objects and advantageswill be best understood from the following detailed description of thepreferred embodiment of the invention shown in the accompanyingdrawings, wherein:

FIG. 1 is a schematic diagram of a system for integrating geothermalenergy with an existing HVAC system, in accordance with features of thepresent invention;

FIGS. 2A-D are schematic diagrams of a method for sealing a cavitationin a well bore, in accordance with features of the present invention;

FIGS. 3A-B depict caliper logs comparing borings made by the inventedprocess to borings made via state of the art processes.

FIG. 4 is an elevated view of a drilling derrick;

FIG. 5 is an elevated view of a multiplier sub, in accordance withfeatures of the present invented system;

FIG. 6 is detailed view of two interacting multiplier subs, inaccordance with features of the present invention;

FIG. 7 is view of FIG. 6 taken along lines 7-7, showing rotation of thetop sub in accordance with features of the present invention; and

FIG. 8 is a view of FIG. 6 taken along lines 8-8, showing rotation ofthe inferior or second sub, in accordance with features of the presentinvention.

DETAILED DESCRIPTION OF THE INVENTION

As used herein, an element or step recited in the singular and proceededwith the word “a” or “an” should be understood as not excluding pluralsaid elements or steps, unless such exclusion is explicitly stated.Furthermore, references to “one embodiment” of the present invention arenot intended to be interpreted as excluding the existence of additionalembodiments that also incorporate the recited features. Moreover, unlessexplicitly stated to the contrary, embodiments “comprising” or “having”an element or a plurality of elements having a particular property mayinclude additional such elements not having that property.

The present invention provides a modular system to facilitate connectionof existing HVAC systems to a geothermal field. Also provided is amethod for establishing a high density geothermal field for use with themodular system.

System Detail

The invented preassembled pod, while stand alone in design, integratessubstantially completely with existing HVAC systems. Typically, noadditional permitting is necessary for installation.

FIG. 1 is a schematic depiction of the system, 10, or subunits of thesystem. Salient features of the system include a means of ingress 24 andmeans of egress 26 of geothermal treated fluid. The fluid can be anyheat exchange media. Typical fluid is enhanced water which compriseswater containing rust inhibitor, antifreeze, and perhaps a balanced pHagent such as a buffer. Enhanced water is a term of art used in thegeothermal industry with such enhanced water constituents dictated bythe manufacturer of the particular heat pump or chiller incorporated inthe system.

The means of ingress 24 establishes fluid communication between thesystem 10 and the fluid. The fluid traverses a closed conduit or loop 30which in turn traverses a geothermal well 13. The loop serves as a heatexchange surface between the fluid and below-ground temperature zones.The means of egress 26 establishes fluid communication between thesystem 10 and the loop which redirects fluid back down the well. Bothmeans are controlled via a flow center 28 or plurality 28 of flowcenters. These flow centers comprise a (or a plurality of) firstcirculation pump(s) which first accept loop fluid from the geothermalwell bore. The first circulation pump directs the fluid to one or aplurality of pretreatment units 27, whereby the fluid is compressed orexpanded to increase or decrease its temperature, respectively.

The temperature of the fluid is compressed or expanded depending on userpreference as embodied in a thermostat 37 setting.

As noted supra, a plurality of air pretreatment units 27 are in fluidcommunication with the flow centers 28. The pretreatment units comprisecompressors or expansion chambers to either compress or expand the fluidfed from the geothermal loop to a target temperature, pursuant to theideal gas law pV=nRT), said temperature determined by user preference.

Intermediate the pretreatment units 27 and the existing building ductwork 42 is positioned a plurality of heat exchange units 30 which areencapsulated in a plenum or some other suitable housing 33. These heatexchange units 30 define a first end 36 to receive supply air and asecond end 38 to exhaust thermally treated air.

As depicted in FIG. 1, each of the heat exchange units comprises thermalconducting surfaces, 31 such as a plurality of fins reminiscent of aradiator, through which thermally treated fluid from the geothermalwells traverses. The fluid is fed to and evacuated from the fins viameans of ingress 35 and egress 37, respectively. Gaps exist between thefins to facilitate air flow contact with the fins of the heat exchangeunits.

A means for establishing air flow across the fins is provided, such thatthe flow traverses from the first end 36 to the second end 38 of theheat exchange units 30. In an embodiment of the invention, the heatexchange units, and the means for establishing air flow, such as a fan41, are contained in a plenum or other such housing.

In operation, air from the building to be heated or cooled is directedbetween and over the fins for a time and at a velocity sufficient toallow heat transfer between the air and the fins. In an embodiment,thermostats 37 or thermocouples are placed aft or downstream of the finsto measure the temperature of the air emanating from between the fins.

The thermally treated air 40 emanates from the second end 38 of the heatexchange units (or is otherwise drawn from the heat exchange units via anegative pressure fan 41) to be taken up by return air conduits 42,which then direct the treated air throughout the HVAC system. As such,the second end of the heat exchange units is situated between the firstends and the return air conduits.

A spent air stream conduit 52 directs depleted air from an egress pointof the HVAC system and directs the depleted air back to the first end 36of the heat exchanger for cooling or heating. A means 53 for supplyingfresh air to the first end 36 is also provided.

Fin 31 temperature is controlled by flow rate of incoming and outgoingloop fluids, as determined by flow controllers 40. The flow controllers40 are in turn monitored by thermostats set at predeterminedtemperatures. In one embodiment, the flow centers 28, heat pumps 27, andflow controllers 40 are all digitally controlled via a user's thermostatsetting.

The entire assembly is contained in a shell or housing 32 which isinsulated from the ambient environment to assure maximum heat transferbetween the loop fluid and the fluid which will course through the HVACsystem or radiant heating system of the structure to be heated and/orcooled. In the case of HVAC systems, the fluid will be air. The air maybe pretreated (such as humidified) prior to or during its dispersalthrough the HVAC system.

In the case of radiant heating systems, the fluid may be water. In oneembodiment, the fluid is the enhanced water, discussed supra. In thisinstance, the enhanced water traverses the already existing water coilsof the building's radiant matrix. As such, the fluid-to-air temperatureheat exchange units 30 found in the aforementioned fluid to air systemsare not utilized.

Housing 32 fabrication materials 39 further provides a means to minimizethermal communication between the inside of the housing and the ambient(i.e. exterior) environment. The ambient environment is construed inthis specification to be the air existing at atmospheric pressure andtemperature external to the outside of the housing 32. Generally, thehousing's fabrication materials 39 provide R ratings appropriate for thetemperature zone in which the assembly is located, and as mandated bylocal building codes. As such, the housing 32 serves as a means tominimize thermal conduction between its interior and the ambientenvironment. The housing, 32, perhaps embodied as a shed or lean-toattached to an existing structure, also provides a physical barrier toany activity external of it.

The fully insulated geoutility pod system may include the followingcomponents:

1. Geothermal heat pumps. Generally, for a typical 3-4 ton load, a heatpump, 27, or a plurality of heat pumps, should be able to move threegallons per ton per minute of geothermal treated fluid. Fluid pressuresof from 22 to 32 psi are suitable. Suitable heat pumps are commerciallyavailable from a myriad of supply companies, including thosemanufactured by Climate Master of Oklahoma City, Okla. Insulationplacement shall be designed in a manner that may eliminate any exposededges to prevent the introduction of glass fibers into the air stream.

2. Vertical heat pumps also may be required. These vertical heat pumpsprovide configurations whereby supply lines (i.e., their exhaust lines)emanate from the top (i.e., superior regions) of their housing whilereturn lines enter their housing from either vertically-disposed side ofthe housing. Suitable vertical heat pumps are commercially availablefrom such supply outlets as Climate Master (referenced supra), Trane(Tyler, Tex. and Piscataway, N.J.) and Ingersoll Rand (Montvale, N.J.).

3. The hot water system. Commercially available units (such as theflexible R Series® Chillers, manufactured by Trane, of Piscataway, N.J.)are adapted to receive incoming water at a temperature range from 20° to110° F. (−6.7° to 43.3° C.) as standard. These are relatively large heatpumps.

4. Refrigerant to air heat exchangers.

5. A solar, wind or fuel cell systems to provide electricity to thecirculating pumps.

6. Any batteries, inverters, etc that are needed to store energy derivedfrom the solar, wind or fuel cell systems.

7. As an option, the geoutility pod system may also have an EnergyManagement system (EMS) that may monitor usage and savings via theinternet.

Heat Exchanger Detail

The heat exchange 30 units comprise a sealed refrigerant circuitincluding a high efficiency scroll, rotary or reciprocating compressordesigned for heat pump operation, a thermostatic expansion valve forrefrigerant metering, an enhanced corrugated aluminum lanced fin andrifled copper tube refrigerant to air heat exchanger (such as thatdepicted as elements 31 in FIG. 1), reversing valve, coaxial (tube intube) refrigerant to water heat exchanger, and safety controls includinga high pressure switch, low pressure switch (loss of charge), water coillow temperature sensor, and air coil low temperature sensor. Accessfittings installed on high and low pressure refrigerant lines facilitatefield service. Activation of any safety device prevents compressoroperation via a microprocessor lockout circuit. The lockout circuitresets at the thermostat or at the contractor supplied disconnectswitch.

In an embodiment of the invention, refrigerant to air heat exchangersutilize enhanced corrugated lanced aluminum fins and rifled copper tubeconstruction rated to withstand 450 PSIG (3101 kPa) refrigerant workingpressure. Refrigerant to water heat exchangers preferably comprisecopper inner water tube and steel refrigerant outer tube design, ratedto withstand 450 PSIG (3101 kPa) working refrigerant pressure and 450PSIG (3101 kPa) working water pressure.

Refrigerant metering can be accomplished by thermostatic expansionvalves. Suitable expansion valves include dual port balanced types withexternal equalizer for optimum refrigerant metering. Suitable units aredesigned and tested for operating ranges of entering enhanced watertemperatures from 20° to 110° F. (−6.7° to 43.3° C.). Suitable reversingvalves include four-way solenoid-activated refrigerant valves, whichdefault to heating mode in the event of solenoid failure. If thereversing valve solenoid defaults to cooling mode, an additional lowtemperature thermostat is preferably provided to prevent over-cooling analready cold room.

Electrical System Detail

A control box 43 is in electrical communication with the flow center 40and the unit compressor 29 compartment and shall contain a 50 VAtransformer, 24 volt activated, 2 or 3 pole compressor contactor,terminal block for thermostat wiring and solid-state controller forcomplete unit operation. Reversing valve and fan motor wiring are routedthrough this electronic controller. Units shall be name-plated for usewith time delay fuses or HACR circuit breakers. Suitable unit controlsare 24 Volt and provide heating or cooling as required by the remotethermostat/sensor.

Solid State Control System (CXM):

Preferably, the system operates via a solid-state control systemembodied in the control box 43 and the flow center 40. The controlsystem microprocessor board protects against building electrical systemnoise contamination, EMI, and RFI interference. The control systeminterfaces with a heat pump type thermostat. The control system has thefollowing features:

a. Anti-short cycle time delay on compressor operation;

b. Random start on power up mode;

c. Low voltage protection;

d. High voltage protection;

e. Unit shutdown on high or low refrigerant pressures;

f. Unit shutdown on low water temperature;

g. Condensate overflow electronic protection;

h. Option to reset unit at thermostat or disconnect;

i. Automatic intelligent reset. For the sake of illustration, the unitmay automatically reset five minutes after trip if the fault hascleared. If a fault occurs three times sequentially without thermostatmeeting temperature, then lockout requiring manual reset may occur;

j. Ability to defeat time delays for servicing;

k. Light emitting diode (LED) on circuit board 43 to indicate highpressure, low pressure, low voltage, high voltage, low water/airtemperature cut-out, condensate overflow, and control voltage status;

l. Optionally, the low-pressure switch is monitored for the first 120seconds after a compressor start command to prevent nuisance safetytrips;

m. 24V output to cycle a motorized water valve or other device withcompressor contactor;

n. Unit Performance Sentinel (UPS). The UPS warns when the heat pump maybe running inefficiently;

o. Water coil low temperature sensing (selectable for water oranti-freeze);

p. Air coil low temperature sensing.

The invented unit provides the eight safety protections of anti-shortcycle, low voltage, high voltage, high refrigerant pressure, lowpressure (loss of charge), air coil low temperature cut-out, water coillow temperature cut-out, and condensate overflow protection.

Enhanced Solid State Control System Detail

This control system features two stage control of cooling and two stagecontrol of heating modes for exacting temperature and dehumidificationpurposes.

This control system coupled with a multi-stage thermostat may betterdehumidify room air by automatically running the heat pump's fan atlower speed on the first stage of cooling thereby implementing lowsensible heat ratio cooling. On the need for higher cooling performance,the system optionally activates the second stage of cooling andautomatically switches the fan to the higher fan speed setting. Thissystem may be further enhanced with a humidistat. Units not havingautomatic low sensible heat ratio cooling may not be accepted; as analternate, a hot gas reheat coil may be provided with control system forautomatic activation.

Control shall have all of the above mentioned features of the CXMcontrol system along with the following expanded features:

a. Removable thermostat connector;

b. Night setback control;

c. Random start on return from night setback;

d. Minimized reversing valve operation (Unit control logic shall onlyswitch the reversing valve when cooling may be demanded for the firsttime. The reversing valve is held in this position until the first callfor heating, ensuring quiet operation and increased valve life.);

e. Override temperature control with 2-hour (adjustable) timer for roomoccupant to override setback temperature at the thermostat;

f. Dry contact night setback output for digital night setbackthermostats;

g. Ability to work with heat pump or heat/cool (Y, W) type thermostats;

h. Ability to work with heat pump thermostats using O or B reversingvalve control;

i. Emergency shutdown contacts;

j. Boilerless system heat control at low loop water temperature;

k. Ability to allow up to 3 units to be controlled by one thermostat;

l. Relay to operate an external damper;

m. Ability to automatically change fan speed from multistage thermostat;

n. Relay to start system pump;

o. 75 VA control transformer. Control transformers feature load sideshort circuit and overload protection via a built in circuit breaker.

Remote Service Sentinel Detail

A solid state control system communicates with thermostats to display(at the thermostats) the unit status, fault status, and specific faultcondition, as well as retrieve previously stored fault that caused unitshutdown. The Remote Service Sentinel allows building maintenancepersonnel or service personnel to diagnose unit from the wallthermostat. For example, the control board may provide a signal to thethermostat fault light, indicating a lockout. Upon cycling the fan input3 times within a 60 second time period, the fault light shall displaythe specific code as indicated by a sequence of flashes. A detailedflashing code may be provided at the thermostat LED to display unitstatus and specific fault status such as over/under voltage fault, highpressure fault, low pressure fault, low water temperature fault,condensate overflow fault, etc.

Embodiments of the invented system contain most of the features listedabove (either CXM or DXM). The control board is supplied with aninterface board to permit all units to be daisy chained via a 2-wiretwisted pair shielded cable. Preferably, the following data points areavailable at a central or remote computer location:

a. space temperature;

b. leaving water temperature;

c. discharge air temperature;

d. command of space temperature setpoint;

e. cooling status;

f. heating status;

g. low temperature sensor alarm;

h. low pressure sensor alarm;

i. high pressure switch alarm;

j. condensate sensor alarm;

k. hi/low voltage alarm;

l. fan “ON/AUTO” position of space thermostat as specified above;

m. unoccupied/occupied command;

n. cooling command;

o. heating command;

p. fan “ON/AUTO” command;

q. fault reset command;

r. itemized fault code revealing reason for specific shutdown fault (anyone of 7)

A myriad of thermostats are available for use with the unit, includingmechanical or electronic types. For example, single stage standardmanual changeover units are suitable in less complex installations.However, for more complex systems, remotely monitored, and/or remotelyactuated, thermostats may be suitable.

Urban Well Drilling And Sealing Detail

The development and application of the aforementioned system is lesssignificant without applying the following invented method forincreasing geothermal flux in small, already established areas, such ascity lots.

The method allows drilling into consolidated formations using rotary muddrilling technologies and solves the lost circulation problems suchformations usually present in rotary mud operations.

Specifically, the invention provides a method for repairing aberrations(often referred to as “fractures”) along a drill bore wall, the methodcomprising: using a rotary mud drill system to produce a drill hole,wherein the system employs a first return mud pressure value; stoppingthe rotary mud drill system when return mud pressure decreases to asecond return mud pressure value at a point P in the drill hole;positioning a reverse auger 22 into the drill hole at said point;rotating the auger; introducing loose substrate “S” into the drill holeso as to cause said loose substrate to contact the auger; lifting andlowering the auger along longitudinally extending regions of the drillhole defining the point and/or above the point P for a time and insubstrate amounts sufficient to minimize the aberrations; andreestablishing the first return mud pressure of the rotary mud drillsystem to extend the length of the drill bore below said point. In oneembodiment of the method, the middle of the auger is placed opposite thepoint P where fracture has occurred and is both rotated and moved up anddown, while substrate S is fed from above. In this instance, substrate Sis directed into the fracture point P before it rolls down the augerflights past the fracture point. Generally, depending or downwardlyfacing surfaces of the auger flights force the substrate down into thedeepest recesses of the bore, as depicted in FIG. 2C.

A salient feature of the method for increasing well flux (i.e., eitherthe number of wells, the depth of wells, or both) is the use of areverse auger system during the drilling process. The reverse auger isdefined as containing left handed flights in the case where the auger isrotated in a right-hand direction. Such a left-handed flightconfiguration is depicted in FIG. 2C.

Right rotation is the drilling standard. However, opposite flighting(i.e., an auger having right handed flights) is suitable when the drillstring operations, and therefore the auger is rotated in a left handdirection. FIGS. 2A-D provide a schematic sequence of this inventedmethod, wherein right-hand rotation is utilized.

The rotational speed and the downward force (weight on bit) applied isdependent on conditions at the point of contact of the bit to thestructure (e.g. the composition of the consolidated structure, the typeof bit, etc). For example, the mud circulation rotary drill bit boringinto limestone might be operated at a bit rpm of 150 rpm to 170 rpm with1000 pound per square inch of weight on the bit (which is empiricallyproven to be effective). Drilling with a tricone bit generally operatesoptimally at a rotational speed of about 30 rpm. Accordingly, drilling apilot hole into bedrock is performed only when deemed absolutelynecessary, and then only for the depth required.

It should be noted that given the hardness of bedrock, and theaforementioned difficulty/expense associated with using mud rotarydrilling techniques to penetrate bedrock, the inventor has devised apilot hole method for facilitating drilling. Briefly, a tricone drillbit (e.g. a Tri-Cone™ bit as distributed by Baker Hughes, Houston, Tex.)is used to first drill a pilot hole into the bedrock. Then, drillingwith the circulating mud/rotating drill bit drilling process cancommence and/or resume.

Often, in bedrock formations, fractures 16 exist, the fractures oftensituated in a transverse disposition to the longitudinal axis a of thewell bore. FIG. 2A shows the rotary bit 14 not yet deep enough to reachthe fracture.

As can be noted in FIG. 2A, a predetermined distance defining an annularspace should be maintained between the walls 17 of the drilled hole andthe drill string surface. The annular space is critical with utilizingmud rotary drilling. This space between the drill pipe string and thewall of the hole being bored must be sufficient to allow drill cuttingsto be pumped away from the drill bit and carried back to surface. Anyobstruction to this annular space will stop the drilling procedure andcan result in loss of thousands of dollars in drilling bits and drillpipe. If the annular space is allowed to become inconsistent or ‘washedout”, then the mud flow to surface is no longer constant with a steadyrate. Drill cuttings start to build up around the drill string causing asimilar loss of the drill bit and/or drill string. As such return mudmust be constantly monitored for pressure, flow rate and amount of drillcuttings being carried back to surface.

Tight calipers (i.e., small variation in the diameter of the well bore),assure a tight packing of the geothermal loop within the hole andtherefore more efficient transfer of geothermal heat from the bedrockand the loop. A well bore diameter “d” between about 3 inches and 10inches is suitable, with “d” between about 4 and 6 inches as preferable.

FIG. 2B depicts the rotary bit 14 piercing the ceiling of the fracture16. Upon such an event, a portion of the drill mud spills into thefracture, as the downward and laterally pointing arrows show. A loss ofmud pressure occurs, and if the fracture is large enough, drilling mustcease. In typical situations, the drilling operator either chooses tostop the depth at that point “P” of the drill bore, or else drillsanother hole.

FIG. 2C depicts the invented reverse auger method in operation. In thisscenario, the operator, upon experiencing mud pressure loss, backs thedrill string out of the hole, and replaces the rotary bit 14 with anauger defining a left hand fl ighting. This auger when rotated to theright, provides a means for forcing downward, thereby pushing aggregateinto the fracture site, 16.

Once the appropriate auger is in place and turning as designated supra,aggregate such as bentonite chips are poured from above into the annularspace defined by the walls 18 of the drilled hole and the drill string12 to which the auger is placed. During insertion of the aggregate, theauger is raised and lowered while also being turned. Continual up anddown movement of the auger causes the aggregate to work its way into theformation at the fracture point P. Essentially, the substrate, fallingfrom above, is manipulated by the auger so as to be below the flights ofthe auger. As such, when the auger is turned, the substrate is forced inone direction (downward), with nowhere else to go but into thefractures. In an embodiment of the invention, the auger prevents upwardmigration of the substrate.

The combination of the raising and lowering of the auger along thelongitudinal axis of the bore hole, plus its rotation (between about 1and 200 rpm) forces the bentonite against the walls 18 and into thefracture 16 of the drilled hole. Rotation speed will vary, depending onthe size of the void or fracture being filled and the amount of pressurerequired to force materials into the voids or fractures.

In one embodiment of the method, the turning of the auger directssubstrate downwardly. When the depending end of the auger is in closespatial relationship to the bottom of the bore, (which may be the caseif mud rotary operations are stopped soon after pressure loss occurs),then the substrate is forced into the fracture space which surrounds thebottom of the bore. In this instance, the auger is moved upwardly from afirst position in the bottom of the bore hole (i.e., from the fracturepoint P). The auger, upon being raised to a second position, or endpoint of its longitudinal movement. The auger is then moved back down toits first position. Movement of the auger may be stopped between thefirst and second points (i.e., at an intermediate point), particularlyin instances where aggregate has completely filled or temporarilyoverloaded the flights of the auger and the aggregate is in the processof being compacted into the fracture point P situated below the auger atthat intermediate point.

The raising and lowering of the auger, combined with the bentonite, alsoserves to smooth close the fracture site, particularly as the blades ofthe auger are in close proximity to the walls of the bore. In oneembodiment of the method, the overall diameter of the auger is chosensuch that only about 2-3 inches clearance exists between the radiallyprojecting flights of the auger blade and the bore wall.

Eventually, the aggregate fills the void created. This is depicted inFIG. 2C. After the fracture 16 is sealed, the drill string is pulledout, the auger is replaced by the rotary drill bit 14, and drillingcontinues, as depicted in FIG. 2D.

The inventor has discovered that the auger manipulations necessary tofill fractures are multi-directional and often simultaneous with eachother. For example, it is not uncommon for the reverse auger to beraised and lowered along the fracture point P several times a minute,while the auger is rotating at the speeds mentioned supra. Ultimately,these manipulations will stress above-hole structures. As such, many ofthe manipulations are not attainable and/or sustainable withconventional equipment. Rather, a multiplier-sub arrangement may berequired, that arrangement disclosed infra. The multiplier-sub is abelow ground connection to the drill string that allows the end of thestring to rotate and speeds which are multiples of the speed that theabove-hole drill string rotates. For example, while the drill stringrotation above the hole is 20 rpms, the rotation at the site of fracturemay need to be faster than 20 rpms.

Furthermore, it should be appreciated that a breach in a well bore wallshould be addressed sooner than later. As such, the auger-multiplier subcombination should be applied on site immediately. Otherwise, in-flowsfrom the formation may cause collapse of the well, or slow but dangerouspressure build up of fluids, which ultimately will breach the surface ofthe well and cause environmental issues. In operation of an embodimentof the reverse auger method, the multiplier sub is removably attached tothe reverse auger and in between the derrick and the reverse auger. Theauger is mated with the depending end of the multiplier-sub in astandard male/female threaded configuration, similar to how sections ofdrill string are attached.

The reverse auger system facilitates heretofore unattained production ofdeep geothermal wells (wherein “deep” is construed herein to be at least300 feet).

Example

FIGS. 3A and 3B are caliper logs depicting a location where fracturedformation and lost circulation zones are an issue. The logs depictfracture zones at depths of 195 feet, 250 feet and 375 feet. These twoholes were drilled 100 feet from each other, on the same day.

FIG. 3A is a caliper log for a hole drilled using conventional drillingtechniques. From a 180 foot depth, a mud rotary was switched to airrotary due to the driller encountering the fractured formation. Caliperdeviations (i.e., washout) seen on that graph are concomitant with lostcirculation.

FIG. 3B is a caliper log for a hole drilled approximately 100 feet awayusing the invented technique. When the invented reverse auger processwas applied at the first instance of mud pressure drop, the fracturessealed, or at least were greatly minimized. The reverse auger method wasused in this drilling at between 180 and 260 feet. Upon repair of thefractures, the mud circulation was reestablished. Unlike the welldepicted in FIG. 3A, the well was completed using mud rotary techniques.

The well which resulted in the caliper log depicted as FIG. 3B provideda more uniform diameter for calculating group specification. The resultsin more efficient geothermal energy conductivity from the formation tothe loops. Also, less spoils are produced, therefore minimizingenvironmental remediation activity.

Application of the invented reverse auger process resulted in a washoutof only 20 percent for the bore produced with the invented method FIG.3B, versus 400 percent washout for the bore produced with standardmethods (FIG. 3A). This means that the bore produced with standardmethods has a four-fold variance in bore diameter throughout its length,versus a variance of approximately 0.2 for the bore produced with theinvented method.

Aggregate/Grout Detail

As to the reverse auger process described supra, a myriad of aggregatetypes are suitable, including but not limited to clays, red mud, cement,asphalt, polymers such as bentonite, volcanic clay material, andcombinations thereof.

Selection of the aggregate types depends on the type of voidexperienced. Generally, aggregate sizes of between ¼″ and ½″ aresuitable. Preferably, if the fracture comprises mainly an aquifer, thenpreferably bentonite, supplied as ⅜ inch chips is suitable inasmuch asit swells upon contact with water. If the fracture is nothing more thana void, then diatomaceous earth is also suitable.

Thus, bentonite or an alternative grout is extruded into the fracture.Most geothermal collection fields are artesian and thus bentonite groutsare nearly ideal sealants. That is, bentonite grouts are flexible and donot shrink and crack when hydrated, thus creating a low permeabilityseal. Also, bentonite grouts are chemically inert, and have generallylow impact to the environment, persons, equipment, and water quality. Ofcourse in situations where excessive chlorides or other contaminantssuch as alcohols or ketones are present, grouts other than bentonite maybe used. At the completion of the sealing operation (when the grout hashardened) the process returns to once again preparing the mud extruder.With the fracture now sealed, pressure can be maintained at a maximallevel (e.g., the first return mud pressure value) so that the bit may beadvanced beyond the fracture.

Optionally, bridging agents are mixed with aggregates in cases wherefractures or cavities experienced in the structure are large. Differentbridging agents are suitable for different situations. In theseinstances, material of a coarse, fibrous or flaky composition are firstapplied with the auger to form an impermeable barrier across a formationinterface or perforation. Such coarse bridging materials are mostcommonly used when lost circulation occurs during drilling. Then,bentonite, or some other final sealing material is applied, also via theauger. Examples of the bridging materials include, but are not limitedto bulk cellulose materials, cotton seed hulls, and manmade materialssuch as Microflake® from Halliburton, or sodium carboxymethyl cellulosesuch as Cellex Pac, provided by Baroid (Houston, Tex.).

Other agents are utilized to bridge and seal formations with low tomoderate porosity and permeability. These solids are added to theaggregate in amounts sufficient to build a filter cake across the porethroat of fractures. These bridging agents include, but are not limitedto acid soluble materials (e.g. calcium carbonate), water solublematerials (e.g. salt such as sodium chloride), water absorbing (e.g.cellulose) or oil soluble resins. Lost circulation material such asmica, nutshells, fiber, diatomaceous earth, is also a suitable additionto the aggregate.

Multiplier-Sub Detail

FIG. 4 is an elevated view of a drill rig 100. Drill rig 100 may be amachine system having tools and accessory equipment to create shaftsand/or boreholes 11 in a ground 9. Drill rig 100 may include mobileequipment mounted on trucks, tracks, or trailers residing on ground 9,or may be attached to ground 9, sometimes as a marine-based structure.In general, drill rig 100 may include the complex of equipment used topenetrate the surface of the earth's crust, which may include a stack ofrock layers interspersed with water, oil, and/or gas.

Drill rig 100 may include a derrick 102, a substructure 104, operationsystems 106, blowout prevention equipment 110, and a drill string 112having a drill bit 202. Derrick 102 may reside on substructure 104 anddrill rig 100 may fix substructure 104 to ground 9. Operation systems106 may reside below, around, and above substructure 104. Drill rig 100may fix blowout prevention equipment 110 to ground 9 about borehole 11.Drill rig 100 may position drill string 112 within borehole 11 and mayconnect drill string 112 to operation systems 106 through blowoutprevention equipment 110.

In operation, operation systems 106 may rotate drill string 112 from atop end to construct borehole 11. Borehole 11 may include cement 15surrounding a casing 21. The system may use cement 15 to fill the spacebetween a wall 17 of borehole 11 and casing 21. Casing 21 may be heavysteel pipe that lines the walls of borehole 11. Together with cement 15,this prevents wall 17 of borehole 11 from caving in, prevents movementof fluids (water, oil, or gas) between rock layers, confines productionto wellbore 11, and provides a way to control pressure utilizing blowoutprevention equipment 110.

Casing 21 may surround a borehole cavity 18. Borehole cavity 18 may bean empty space within casing 21 that extends from blowout preventionequipment 110 at a borehole cavity top 19 to a borehole cavity bottom20. The distance between blowout prevention equipment 110 and boreholecavity bottom 20 typically is about 15,000 feet (4.6 km) long for an oilor gas well vertically drilled onshore. The excess in the diameter ofborehole cavity 18 over a diameter of drill string 112 is an overgauge22. Overguage 22 may be an annular gap whose distance may varyvertically along borehole cavity 18. Overguage 22 may be a passageway toallow drilling mud fluid 154 to carry fragmented cuttings 156 fromborehole cavity bottom 20 to blowout prevention equipment 110. Duringthe process of drilling, drill rig 100 continuously circulatespressurized drilling fluid (mud) down a center of drill string 112, outof holes in drill bit 202 at the bottom of drill string 112, and back upto the surface via the overgauge 22 space between the rotatingdrill-string 112 and casing 21. The circulated drilling mud 154 coolsand lubricates drill bit 202 as well as to remove cuttings 156 producedby drill bit 202.

As noted above, drill rig 100 may include derrick 102. Derrick 102 maybe a large load-bearing structure arranged as a bolted construction ofmetal beams 114. As a framework erected over borehole 11 to allow drillrig 100 to lift-up and lower drill tubes, derrick 102 may include fourderrick legs 116 residing on substructure 104 and a derrick crown 118 asa topmost part of derrick 102 to form an upstanding mast. Derrick 102may be pyramidal in shape, extend from 30 to 60 meters abovesubstructure 104, and offer a good strength-to-weight support ratio.

Substructure 104 may be an assembly of heavy substructure beams 120supporting a substructure platform 122 above ground 9. Drill rig 100 mayuse substructure 104 as a foundation to elevate derrick 102 and providespace underneath. Drill rig 100 may utilize this space underneath toinstall equipment for operation systems 106 on a cellar deck 124 and toinstall blowout prevention equipment 110 adjacent to a wellhead 126.Wellhead 126 may be an area immediately surrounding borehole cavity top19.

Operation systems 106 may be an arrangement of power controlling devicesutilized to impart electrical, mechanical, and other energy into drillrig 100. Operations system 106 may include a rotary system 128, ahoisting system 130, and a drilling mud circulation system 132. Inaddition, operations system 106 may include engines 133. Engines 133 mayinclude any of various types of power units such as a hydraulic,internal combustion, air, or electric motor that develops energy orimparts rotary motion to power other machines.

Rotary system 126 may impart controlled rotational motion into drillstring 112. Rotary system 126 may include a rotary drive 134, a rotaryhead 136, a rotary table 138, a kelly drive 140, and a swivel 142. Drillrig 100 may connect kelly drive 140 between swivel 142 and rotary table138. In addition, drill rig 100 may secure rotary drive 134 tosubstructure platform 122, may connect rotary table 138 to rotary drive134, and may connect rotary head 136 adjacent to borehole cavity top 19.

Rotary drive 134 may be a machine utilized to impart rotational power todrill string 112 while permitting vertical movement of pipe fordrilling. Rotary drive 134 may include a rotary/master bushing to turn akelly drive bushing to permit up and down movement of kelly drive 140while the drill pipe 170 is turning.

Rotary head 136 may provide a reasonably tight seal at the top of wellpipe casing 21 while permitting kelly drive 140 to rotate therein. Drillrig 100 may provide rotary head 136 with a 16-inch diameter pipe securedto a conductor pipe of casing 21. Rotary head 136 may facilitatehandling drilling mud flowing upward through casing 21.

A kelly tool may be a heavy square, hexagonal or octagonal shaped tubingmember suspended from swivel 142 through rotary table 138 and connectedto a topmost section of drill pipe 170 to turn drill pipe 170 as rotarytable 138 turns. The upper end of the kelly is screwed into swivel 142,usually using a left-hand thread to preclude loosening from theright-hand torque applied below. The kelly tool fits into the kellybushing—a mechanical device that turns the kelly when rotated by rotarytable 138. Together, the art refers to the kelly and the kelly bushingas kelly drive 140. Kelly drive 140 is how drill rig 100 applies themotive power to rotate the drill string 112 to drill at borehole cavitybottom 20.

Swivel 142 may be a mechanical device that suspends the weight of drillpipe 170, provides for the rotation of the drill pipe 170 beneath itwhile keeping the upper portion stationary, and permits the flow ofdrilling mud 154 from a standpipe 162 without leaking. Swivel 142 mayhang directly under a traveling block 150 of hoisting system 130directly above kelly drive 140. Swivel 142 may provide the ability forthe kelly and subsequently drill string 112 to rotate while allowinghoisting system 130 to remain in a stationary rotational position. Inaddition, swivel 142 may allow vertical movement of drill string 112 upand down derrick 102 while simultaneously allowing the introduction ofdrilling fluid into drill string 112.

Hoisting system 130 may be a collection of parts that cooperate to raiseor haul up with mechanical help. Hoisting system 130 may include adrawworks 144, a drilling cable 146, a crown block 148, a travelingblock 150, and a lifting hook 152—a device to grab and lift loadsthrough a hoist. Drill rig 100 may connect lifting hook 152 betweentraveling block 150 and swivel 142. Drill rig 100 may connect crownblock 148 to derrick crown 118 and may secure drawworks 144 tosubstructure platform 122. In addition, drill rig 100 may pass drillingcable 146 from drawworks 144, around crown block 148, and aroundtraveling block 150.

Drawworks 144 may be a machine on drill rig 100 having a large-diametersteel spool, brakes, a power source, and assorted auxiliary devices. Asa large winch, drawworks 144 may spool off or take in drillingcable/line 146 to raise or lower drill string 112. Drilling cable 146may be a large diameter, multi-thread, twisted wire rope that drill rig100 runs run over, threads through, or reeves through crown block 148and traveling block 150. This gives the arrangement a mechanicaladvantage in a “block and tackle” or “pulley” fashion. Drilling cable146 may facilitate the lowering and lifting of drill string 112 into andout of wellbore 11. The art refers to the drill line from drawworks 144to crown block 148 as the fast line 153. Gravity may reel out drillingcable 146 from drawworks 144 and engines 133 may take in drilling cable146.

Crown block 148 and traveling block 150 each may be an assembly ofsheaves. A sheave may be a wheel or roller with a groove along its edgefor holding a belt, rope, or cable. When hung between two supports andequipped with a belt, rope, or cable, one or more sheaves make up apulley. The sheaves may receive drilling cable 146. Crown block 148 maybe mounted on derrick beams 114 at derrick crown 118 of derrick 102.Traveling block 150 may be secured within drilling cable 146 and move upor down in derrick 102.

Drilling mud circulation system 132 may be a group of independent butinterrelated elements that cooperate to circulate drilling fluid 154into and out of borehole 11. Drilling fluid 154 may be a fluid such aswater based and non-aqueous mud or gaseous drilling fluid used to drillboreholes into the earth. Drilling fluid 154 may provide hydrostaticpressure within wellbore 11 to prevent formation fluids from enteringinto wellbore 11. In addition, drilling fluid 154 may keep drill bit 202cool and clean during drilling, and may carry out drill cuttings 156from wellbore 11. This description may use the term mud, drilling mud,and drilling fluid 154 interchangeable.

Drilling mud circulation system 132 may include a mud pump 158, a mudpit 160, a standpipe 162, a kelly hose 164, and a mud return line 166.Drill rig 100 may connect mud pump 158 to mud pit 160. Drill rig 100 mayposition standpipe 162 between mud pump 158 and kelly hose 164. Inaddition, drill rig may connect kelly hose to drill string 112 and mayconnect mud return line 166 between overgauge 22 of borehole cavity 18and mud pit 160. In operation, mud pump 158 may draw mud 154 from mudpit 160 to pass mud 154 down through standpipe 162, kelly hose 164,drill string 112, and up through casing annulus 25 and mud return line166 to return mud 154 and the retrieved cuttings 156 to mud pit 160.

Mud pump 158 may be a large, high-pressure reciprocating pump used tocirculate drilling mud 154 on drill rig 100. Mud pit 160 may be a steeltank secured to ground 9 or an open pit dug in ground 9 to hold drillingmud 154 or waste materials such as well bore cuttings or drilling mudsediments. Standpipe 162 may be a rigid metal conduit fixed to metalbeams 114 to provide a pathway for drilling mud 154 to travel aboutone-third of the way up derrick 102, where it connects to kelly hose164. Kelly hose 164 may be a flexible, steel reinforced, high pressurehose that connected to swivel 142 to connect standpipe 162 to agoose-neck on swivel 142 above the kelly. Kelly hose 164 allows freevertical movement of the kelly while facilitating the flow of drillingfluid 154 through the system and down drill string 112. Mud return line166 may be a pipe to connect mud pathways in blowout preventionequipment 110 to mud pit 160.

Blowout prevention equipment 110 may include a large valve connected torotary head 136 that can seal off at the surface wellhead 19. Blowoutprevention (BOP) equipment 110 may include preventers, spools, valves,and nipples connected to the top of wellhead 19 to prevent theuncontrolled escape of oil or gas. During drilling or wellinterventions, drill rig 100 remotely may close off the hydraulicallyactuated valve if overpressure from an underground zone causes formationfluids such as oil or natural gas to enter wellbore 11 and threatendrill rig 100. By closing this valve, the drilling crew can preventexplosive pressure release, thus regaining control of the downholepressure.

Drill string 112 may be a hollow column/string of mechanical componentsto transmit rotational power and drilling fluid to a drill bit 202.Drill string 112 may include a transition pipe 168, a drill pipe 170 (ordrill rod 170), and a bottom hole assembly 200 joined together in seriesusing special threaded connections such as tool joints. Drill string 112may be hollow to allow drill rig 100 to pump drilling fluid 154 downthrough drill string 112 and circulated back up annulus 25, sinceannulus 25 presents a void between drill string 112 and formationborehole 11.

Transition pipe 168 may be a heavyweight drill pipe (HWDP) to make aflexible transition between drill collars and an upwardly directed endof a drill pipe 170. This helps to reduce the number of fatigue failuresseen directly above bottom hole assembly 200. A secondary use oftransition pipe 168 is to add additional weight to drill bit 202.

Drill pipe 170 may be heavy seamless steel tubing utilized to rotatedrill bit 202 and circulate drilling mud 154. Each section of drill pipe170 may be about 30 feet long, where threaded tool joints may fastenthem together. In addition, drill string 112 may use drill stem subs toconnect drill string 112 elements. Drill string 112 typically may beabout 15,000 feet (4.6 km) long for an oil or gas well verticallydrilled onshore in the United States and may extend to over 30,000 feet(9.1 km) for an offshore deviated (non-vertical) well. Drill pipes 170makes up the majority of drill string 112.

The below description provides details on a multiplier sub 300 (FIG. 5).The multiplier sub 300 may be utilized as part of a bottom hole assembly200 in a drill rig to maintain a desired revolutions per minute (rpm) ofa drill bit 202 while decreasing the speed of rotary equipment such asdrill rods 170, a rotary head (not shown), and a rotary table (notshown).

For example, a drill rig may include an above ground tool drive primemover and may operate both the drill bit 202 and the above-ground rotaryequipment at 200 rpms. However, a drill rig utilizing a series of twomultiplier subs in a drill string 12 may operate the aboveground rotaryequipment at 50 rpm. The first multiplier sub may double the 50 rpmspeed to 100 rpm. The second multiplier sub then may double the 100 rpmto 200 rpm so that the drill bit 202 turns at the desired 200 rpm. Therelatively slower 50 rpm speed of drill rods 170, a rotary head, and arotary table reduce the vibrations experienced in the drill rig. Inaddition to this below ground mechanical system reducing vibrations inthe above ground drill rig 100, the multiplier sub 300 provides benefitssimilar to that of a downhole motor without the added cost of a separatehigh-pressure drilling mud system needed to operate a down-hole motor.Various elements of conventional rotating drilling systems referencedthroughout this portion of the specification, including above-groundportions of such systems, are found in textbooks and widely disseminatedliterature related to oil and gas well drilling, including, but notlimited to, R. Baker, “A Primer of Oilwell Drilling” (5th Edition,Petroleum Extension Service, Univ. of Texas, Austin, 1996), the entiretyof which is incorporated herein by reference.

FIG. 5 is a detailed view of a bottom-hole assembly 200. The bottom-holeassembly (BHA) 200 may be the lowest 70-100 meters portion of the drillstring. As a group of components that make up the lower end of the drillstring, the bottom-hole assembly 200 may include the drill bit 202, adrill bit sub 204, a first multiplier sub 206, and a second multipliersub 208. The bottom hole assembly 200 may connect the first multipliersub 206 and the second multiplier sub 208 together and may connect thedrill bit sub 204 between the drill bit 202 and the second multipliersub 208.

The bottom-hole assembly 200 additionally may include drill collars,which are heavy, thick-walled tubulars, used to apply weight to thedrill bit 202, and stabilizers to keep the drilling assembly centered inthe borehole 11. The bottom-hole assembly 200 also may contain othercomponents such as a rotary steerable system, a measurement whiledrilling (MWD) tool, and a logging while drilling (LWD) tool. The drillbit 202, drill bit sub 204, first multiplier sub 206, and secondmultiplier sub 208 are discrete components and the bottom hole assembly200 may place other elements between them.

The drill bit 202 may be a boring and cutting element used in drillingwellbores to break-up the rock formations. The drill bit 202 may behollow and include jets to allow for the expulsion of drilling fluid athigh velocity and high pressure to help clean the drill bit 202 and helpto break apart softer rock formations. The drill bit 202 may includecutting elements 210 connected to a circulating element 212. The drillbit 202 may connect the circulating element 212 to a drill bit pinconnector 214. The drill bit 202 may advance inwardly into earth 9 fromthe point at which the drill bit 202 pierces earth 9 and acts on theentire peripheral extent of the borehole 11 as the drill bit 202advances.

The cutting elements 210 may be a roller-cone device attached to the endof the drill string 12 having cutters to break apart, cut, or crush rockformations when drilling the wellbore 11. In one example, the cuttingelements 210 may be part of a polycrystalline diamond compact (PDC)cutter as discussed, supra. The circulating element 212 may permit thepassage of drilling fluid (such as mud) and may use hydraulic force ofdrilling mud to improve drilling rates. The drill bit pin connector 214may be a male threaded part of a thread coupling having a cooperatingfemale thread box to mate two discrete parts of the drill string 12. Thedrill bit pin connector 214 may be a rotary-shouldered tool joint havinga conical shape.

“Sub-” is a prefix that may mean under or below. In wellbore drilling,subs are small sections of pipe run between and below drill collars andother drill string elements to do various functions. The bottom holeassembly 200 may use the drill bit sub 204 to make a connection betweendrill bit 202 and the second multiplier sub 208. The drill bit sub 204may include a drill bit sub box connector 216 connected to a drill bitsub pin 218 via a drill bit sub body 220. The bottom hole assembly 200may screw the drill bit pin connector 214 into the drill bit sub boxconnector 216 and secure the two together with a cotter pin, forexample. Here, the drill bit pin connector 214 and the drill bit sub boxconnector 216 may form a pin-to-box joint where one end of thismale-to-female coupling is threaded on the outside (pin) and theopposite end threaded on the inside (box).

In operation, the drill pipe 170 and an outside portion of the firstmultiplier sub 206 may spin in a clockwise direction (i.e., a right handrotation) shown by a first arrow 222. FIG. 7 provides an axial view ofthis rotation.

The right hand rotation of the superior or first sub causes both aninside portion of the first multiplier sub 206 and an outside portion ofthe second multiplier sub 208 to rotate in an opposite direction, namelyin a counterclockwise (i.e., left hand rotation) direction shown by asecond arrow 224. FIG. 8 provides an axial view of this left handrotation.

The simultaneous left hand and right hand rotations of the first andsecond multiplier subs respectively causes an inside portion of thesecond multiplier sub 208, drill bit sub 204 and drill bit 202 to rotatein the originally intended direction, namely a clockwise direction (i.e.right hand direction) shown by a third arrow 226. Here, the rotationalspeed of bottom hole assembly 200 may increase by a factor of two foreach change in direction. Thus, as the drill pipe 170 is rotated at 50rpms, the first multiplier sub 206 will multiply that speed by a factorof two to increase it from 50 rpms to 100 rpms. The second multipliersub 208 then may increase that 100 rpms by a factor of two, so that thedrill bit 202 eventually turns at 200 rpms—or some other desiredrotational speed.

FIG. 6 is a side, elevated view of the multiplier sub 300. A drill rigmay utilize the multiplier sub 300 to form an elongated hole 11 bydislocating solid material of the earth 9. The multiplier sub 300 may bea device to multiply the revolutions per minute of drill pipe 170 aboveit. Rather than requiring a separate mud machine to push extremely highpressure mud into a downhole motor to turn the drill bit as in U.S. Pat.No. 4,613,002 (Pitman et al.), the drill rig 200 may mechanically drivethe multiplier sub 300 with the torque of drill pipe 170 itself toincrease the revolutions per minute of drill bit 202. Here, themultiplier sub 300 may be a drilling sub designed to mechanicallyincrease the rotations per minute (RPM) of drill bit 202 withoutincreasing the speed of drill rods 170, rotary head, or rotary table 138above hole. The multiplier sub 300 will have benefits expected from adownhole motor without the added cost of high pressure drilling mudsystems to operate the device. In one example, the multiplier sub 300may have an overall length of approximately thirty inches.

The multiplier sub 300 may include a sleeve 302, a mandrel 304, a firstgear cluster 402, a second gear cluster 404, a mandrel bearing 310, anupper bearing 312, an intermediate bearing 314, a lower bearing 316, anda lock 318. The multiplier sub 300 may arrange the mandrel bearing 310,the first gear cluster 402, the intermediate bearing 314, second gearcluster 404, lower bearing 316, and lock 318 top down within the sleeve302 in series to form a stack centered on a main axis 320. Themultiplier sub 300 may center the mandrel 304 on the main axis 320within this stack to extend out of the sleeve 302. The drill string 12may attach the second multiplier sub 206 or drill bit sub 204 to themultiplier sub 300. In operation, the drill string 12 may spin thesleeve 302 in a first direction at a first speed. The first gear cluster402 and second gear cluster 404 may increase this speed so that thesecond gear cluster 404 changes directions and speeds up.

The sleeve 302 may be a tubular form open at two ends to receive itemstherein. It may include a pin connector 322 attached to a sleeve tube324. The sleeve 302 may further include a sleeve outer surface 326 and asleeve inner surface 328 sandwiched between a sleeve top 330 and asleeve bottom 332.

The pin connector 322 may be a threaded male connector to engage femalethreads to form a rigid sealed pipe joint. The pin connector 322 mayreceive motion from uprotation components. The pin connector 322 mayinclude pin threads 334 extending radially outward from sleeve top 330to a pin base 336 and a make and break pin shoulder 338 positionedaround pin base 336 and positioned above a pin tong area 340. That areawithin the sleeve inner surface 328 from the sleeve top 330 through pintong area 340 may form a pin fluid conduit 342. The pin fluid conduit342 may be a hollow cylindrical shape through which drilling mud maypass downward.

The sleeve tube 324 may be a long, hollow, cylindrical object tocontinue rotational motion from the pin connector 322 and impart thatrotational motion to elements within sleeve tube 324. In one example,the sleeve tube 324 may have a thickness of ½ to ¾ inch, and may includea sleeve tube interior 344 as a hollow space surrounded by sleeve innersurface 328 and accessible through a sleeve tube interior opening 346.The sleeve tube 324 may include a first sleeve teeth set 348 and asecond sleeve teeth set 350 secured within the sleeve tube interior 344and separated by a sleeve bearing gap 352.

The first sleeve teeth set 348 and second sleeve teeth set 350 each mayinclude a number of uniform linkages that project radially inwardtowards main axis 320 to mesh with and drive other gear teeth. Eachtooth shape may be part of a segment of a straight edge or a curvedshape such as a helix. A user may produce first the sleeve teeth set 348by machining material from sleeve inner surface 328. The second sleeveteeth set 350 may be a removable teeth ring that a user may fix in placeand remove to with a same or different sized set of the second sleeveteeth set 350. The first sleeve teeth set 348 may define a first sleeveteeth set length 354.

The sleeve bearing gap 352 may be an empty space between the firstsleeve teeth set 348 and second sleeve teeth set 350 to receive theintermediate bearing 314. As discussed below, the sleeve bearing gap 352also may act as a lubrication reserve. It may further define a sleevebearing gap length 356 as measured between the first sleeve teeth set348 and second sleeve teeth set 350.

The sleeve outer surface 326 may be a cylindrically shaped, radial outerboundary of the sleeve 302 facing away from the main axis 320. Thesleeve inner surface 328 may be a discontinuous inner boundary of sleeve302 facing towards the main axis 320. The sleeve top 330 may be anuppermost part of the sleeve 302 and the sleeve bottom 332 may be alowermost part of the sleeve 302.

The mandrel 304 may be a tubular form to cooperate with the sleeve 302in transferring motion from the sleeve 302 to the mandrel 304. Inaddition, the mandrel 304 may be open at two ends to allow downwardpassage of drilling fluid 154. It may include a box connector 358attached to a mandrel tube 360. It may further include a mandrel outersurface 362 and a mandrel inner surface 364 sandwiched between a mandreltop 366 and a mandrel bottom 368.

The box connector 358 may be a threaded female connector to engage malethreads to form a rigid sealed pipe joint. The box connector 358 mayinclude box threads 370 extending radially inward as part of acounterbore from the mandrel bottom 368 to a box base 372. The boxconnector 358 may include a make and break box shoulder 374 positionedas part of the mandrel bottom 368 and positioned below a box tong area376.

The mandrel tube 360 may be a long, hollow, cylindrical object so as toreceive motion from the sleeve 302 through the first gear cluster 402and second gear cluster 404 and impart that rotational motion to boxconnector 358. That area within mandrel inner surface 364 from themandrel top 366 through the box tong area 376 may form a box fluidconduit 378. This conduit 378 may be a hollow cylindrical shape toreceive drilling mud from pin fluid conduit 342 to pass the muddownward. In one example, the box fluid conduit 378 may have a diameterof approximately 1-½ inches.

The mandrel tube 360 may include a mandrel tube exterior surface 380 asan exterior surface surrounding the mandrel inner surface 364. Themandrel tube 360 may include a first mandrel teeth set 384 and a secondmandrel teeth set 386 secured within the mandrel tube exterior 380 andseparated by a mandrel bearing gap 388. The first mandrel teeth set 384and second mandrel teeth set 386 each may include a number of uniformlinkages that project radially outward away from the main axis 320 andtowards the first sleeve teeth set 348 and second sleeve teeth set 350to mesh with and drive other gear teeth. Each tooth shape may be part ofa segment of a straight edge or a curved shape such as a helix. A usermay produce the first mandrel teeth set 384 by machining material fromthe mandrel tube exterior surface 380. The second mandrel teeth set 386may be a removable teeth ring that a user may fix in place and remove towith a same or different sized set of second mandrel teeth set 386.

The mandrel bearing gap 388 may be an empty space between the firstmandrel teeth set 384 and second mandrel teeth set 386 to receive theintermediate bearing 314. As discussed below, the mandrel bearing gap388 also may cooperate with the sleeve bearing gap 352 to act as alubrication reserve. The mandrel outer surface 362 may be adiscontinuous inner boundary of the mandrel 304 facing away from themain axis 320. The mandrel inner surface 364 may be a cylindricallyshaped, radial inner boundary of the mandrel 304 facing towards the mainaxis 320. The mandrel top 366 may be an uppermost part of the mandrel304 and the mandrel bottom 368 may be a lowermost part of the mandrel304.

The first gear cluster 402 may be a grouping of pin gears 406 positionedbetween the first sleeve teeth set 348 and the first mandrel teeth set384 to reside radially around main axis 320. Each pin gear 406 may be anelongated pin gear cylinder 408 having pin gear teeth 410 that projectradially outward from a pin gear axis 412. Each tooth shape may be partof a segment of a straight edge aligned parallel to the axis of rotation412 or a curved shape such as a helix. The pin gear 406 may include afirst upper stem 414 and a first lower stem 416 centered on pin gearaxis 412 and extending from pin gear cylinder 408 in oppositedirections. The pin gear 406 may have a pin gear length 418 as measuredfrom one end of the pin gear cylinder 408 to the other. The upperbearing 312 and intermediate bearing 314 may hold the first gear cluster402 in position while allowing each pin gear 406 to rotate around itsaxis 412.

FIG. 7 is a section view of multiplier sub 300 taken along line 7-7 ofFIG. 6. As noted above, first gear cluster 402 may be a grouping of pingears 406 positioned between the first sleeve teeth set 348 and thefirst mandrel teeth set 384 to reside radially around main axis 320. Inthis example, first gear cluster 402 may include six pin gears 406equally spaced around the main axis 320. A limit diameter may be adiameter on a gear at which a line of action intersects a maximumaddendum circle of the mating gear for an external gear and intersects aminimum addendum circle of the mating gear for an internal gear. Eachpin gear 406 may include a first pin gear limit diameter 420. In oneexample, the first pin gear limit diameter 420 may range from ⅝ to ¾inches.

The second gear cluster 404 of FIG. 6 may be a grouping of pin gears 422positioned between the second sleeve teeth set 350 and second mandrelteeth set 386 to reside radially around the main axis 320. Each pin gear422 may be an elongated pin gear cylinder 424 having pin gear teeth 426that project radially outward from a pin gear axis 428. Each tooth shapemay be part of a segment of a straight edge aligned parallel to the axisof rotation 428 or a curved shape such as a helix. The Pin gear 422 mayinclude a second upper stem 430 and a second lower stem 432 centered onthe pin gear axis 428 and extending from the pin gear cylinder 424 inopposite directions. The pin gear 422 may have a pin gear length 434 asmeasured from one end of pin gear cylinder 424 to the other. Theintermediate bearing 314 and lower bearing 316 may hold second gearcluster 404 in position while allowing each pin gear 422 to rotatearound its axis 428.

Each pin gear 422 may include a second pin gear limit diameter 438. Inone example, the second pin gear limit diameter 438 may be differentfrom the first pin gear limit diameter 420. In practice, the first gearcluster 402 will receive the load before the second gear cluster 404potentially to cause uneven wear between the two gear clusters. Bymaking the second pin gear limit diameter 438 different from first pingear limit diameter 420, multiplier sub 300 may work to adjust thetransmitted load to be balanced between the first gear cluster 402 andsecond gear cluster 404 so that each gear system may experiencesubstantially similar wear. In one example, the second pin gear limitdiameter 438 may be more than the first pin gear limit diameter 420. Inanother example, second pin gear limit diameter 438 may be ninetypercent of the first pin gear limit diameter 420.

The mandrel bearing 310 may be a support placed between pin tong area340 and mandrel top 366 to allow them to move easily. In addition topermitting rotation between the parts, the mandrel bearing 310 may takethrusts from mandrel 304 parallel to the main axis 320 of revolution tosupport a high axial load while permitting rotation between the pinconnector 322 and mandrel tube 360. The mandrel bearing 310 also may actas a seal to prevent leakage of lubrication fluid and drilling fluid154. The multiplier sub 300 may position mandrel bearing 310 withinsleeve tube interior 344 and secure mandrel bearing 310 within a seatformed in pin tong area 340.

The upper bearing 312 may be a device to allow constrained relativemotion between the sleeve tube 324 and mandrel tube 360 so that each mayrotate with very little rolling resistance and with little sliding. Inaddition to allowing rotation movement of the sleeve tube 324 andmandrel tube 360, the upper bearing 312 may function as an upper supportfor the first gear cluster 402 and allow each pin gear 406 to rotateabout its pin gear axis 412 while taking thrusts from the first gearcluster 402 parallel to the main axis 320 of revolution. The upperbearing 312 also may act as a seal to prevent leakage of lubricationfluid and drilling fluid 154. The multiplier sub 300 may position upperbearing 312 within the sleeve tube interior 344 and secure the upperbearing 312 against the pin tong area 340 between the sleeve tube 324and mandrel tube 360. The multiplier sub 300 may rotatably fix eachfirst upper stem 414 within upper bearing 312.

The intermediate bearing 314 allows constrained relative motion betweensleeve tube 324 and mandrel tube 360 so that each may rotate with verylittle rolling resistance and with little sliding.

In addition to allowing rotation movement of the sleeve tube 324 andmandrel tube 360, the intermediate bearing 314 may function as anintermediate support for the first gear cluster 402 and second gearcluster 404. The intermediate bearing 314 may allow each pin gear 406and each pin gear 422 to rotate about its pin gear axis while takingthrusts from the first gear cluster 402 and second gear cluster 404parallel to the main axis 320 of revolution. The intermediate bearing314 also may act to allow lubrication fluid to flow through intermediatebearing 314. The multiplier sub 300 may position intermediate bearing314 within the sleeve tube interior 344 and secure the intermediatebearing 314 between the sleeve tube 324 and mandrel tube 360. Themultiplier sub 300 may rotatably fix each first lower stem 416 and eachsecond upper stem 430 within intermediate bearing 314.

The lower bearing 316 allows constrained relative motion between thesleeve tube 324 and mandrel tube 360 so that each may rotate with verylittle rolling resistance and with little sliding. In addition toallowing rotation movement of sleeve tube 324 and mandrel tube 360, thelower bearing 316 may function as a lower support for the second gearcluster 404 and allow each pin gear 422 to rotate about its pin gearaxis 428 while taking thrusts from the second gear cluster 404 parallelto the main axis 320 of revolution. The lower bearing 316 also may actas a seal to prevent leakage of lubrication fluid and drilling fluidcarrying fragmented cuttings. The multiplier sub 300 may position thelower bearing 316 within sleeve tube interior 344 at a position aboveand against the lock 318 and secure the lower bearing 316 between thesleeve tube 324 and mandrel tube 360. The multiplier sub 300 mayrotatably fix each second lower stem 432 within lower bearing 316.

The lock 318 may be a threaded ring that may hold elements within thesleeve tube interior 344. The lock 318 may screw into the sleeve tubeinterior 344 at a position near the sleeve bottom 332. The main axis 320may be a straight line through multiplier sub 300 to act as a centeraround which the multiplier sub 300 may rotate.

When assembled, multiplier sub 300 defines a lubrication channel 390.The lubrication channel 390 may be an empty space between the sleevetube 324 and mandrel tube 360 and between the components residingbetween sleeve tube 324 and mandrel tube 360. The multiplier sub 300 maypack the lubrication channel 390 with lubricant such as oil, grease, orother friction-lessening substance to reduce friction and minimizeheating. In addition to lubricating the mandrel bearing 310, upperbearing 312, intermediate bearing 314, and lower bearing 316, thelubricant 392 may lubricate first gear cluster 402 and second gearcluster 404.

A teeth ratio between sleeve 302, mandrel 304, and first gear cluster402 and between sleeve 302, mandrel 304, and second gear cluster 404 maybe such that the rotational speed of sleeve 302 may be stepped upwardsby a multiple so that a rotational speed of mandrel 304 may be greaterthan a rotational speed of the sleeve 302. In one example, the teethratio may step up the rotational speed of sleeve 302 by a multiple oftwo so that the mandrel 304 spins twice as fast as the sleeve 302.Generally, the invented multiplier sub can impart rotation speeds to thebit 14, or 212 that are between approximately 2 to 6 times faster thanthe rotation of the drill string 12 or sleeve 302.

It is to be understood that the above description is intended to beillustrative, and not restrictive. For example, the above-describedembodiments (and/or aspects thereof) may be used in combination witheach other. In addition many modifications may be made to adapt aparticular situation or material to the teachings of the inventionwithout departing from its scope. While the dimensions and types ofmaterials described herein are intended to define the parameters of theinvention, they are by no means limiting and are exemplary embodiments.Many other embodiments will be apparent to those of skill in the artupon reviewing the above description. The scope of the invention should,therefore, be determined with reference to the appended claims, alongwith the full scope of equivalents to which such claims are entitled. Inthe appended claims, the terms “including” and “in which” are used asthe plain-English equivalents of the terms “comprising” and “wherein.”Moreover, in the following claims, the terms “first,” “second,” and“third,” are used merely as labels, and are not intended to imposenumerical requirements on their objects. Further, the limitations of thefollowing claims are not written in means-plus-function format and arenot intended to be interpreted based on 35 U.S.C. §112, sixth paragraph,unless and until such claim limitations expressly use the phrase “meansfor” followed by a statement of function void of further structure.

The embodiment of the invention in which an exclusive property orprivilege is claimed is defined as follows:
 1. A system for adapting anHVAC system in an existing building for utilizing geothermal energy, thesystem comprising: an incoming flux of geothermal energy; a plurality ofheat exchange surfaces adapted to receive the incoming flux ofgeothermal energy; and an interface between the HVAC system and the heatexchange surfaces, said interface adapted to transfer the geothermalenergy to the system.
 2. The system as recited in claim 1 wherein theincoming flux of geothermal energy comprises thermally treated fluid ata pressure of between 20 psi and 40 psi.
 3. The system as recited inclaim 2 wherein the fluid has a vapor pressure greater than or equal towater.
 4. The system as recited in claim 2 wherein the fluid is water,or alcohol, or air and combinations thereof.
 5. The system as recited inclaim 1 wherein the interface is maintained in a controlled environment.6. The system as recited in claim 1 wherein said plurality of heatexchange surfaces provides at least 30 tons of energy to the HVACsystem.
 7. A drill rig comprising a multiplier sub having an aboveground drive motor to form an elongated hole by dislocating solidmaterial from earth and a below ground mechanical system to reducevibration in a drill rig connected to a drill pipe, a drill bit, and anabove ground drive motor to form an elongated hole in earth bydislocating solid material from earth and a bottom-hole assembly havingan above ground drive motor to form an elongated hole by dislocatingsolid material of the earth.
 8. The drill rig of claim 7 wherein themultiplier sub having an above ground drive motor to form an elongatedhole by dislocating solid material from earth comprises: a sleeve havinga threaded male connector attached to a sleeve tube, where the sleevetube includes an sleeve tube interior surface lined with teeth; amandrel having a threaded female connector attached to a mandrel shaft,where the mandrel shaft is positioned within the sleeve tube andincludes a mandrel shaft exterior surface lined with teeth; a first gearcluster having a plurality of first gear cluster pin gears positionedwithin the sleeve tube between teeth of the sleeve and mandrel; and asecond gear cluster having a plurality of second gear cluster pin gearspositioned within the sleeve tube between teeth of the sleeve andmandrel, where the first gear cluster is separated from the second gearcluster by an intermediate bearing, and where a teeth ratio between thesleeve the mandrel, the first gear cluster, and the second gear clusteris a value that configures the mandrel to spin at least twice as fast asthe sleeve.
 9. The multiplier sub of claim 8, where a diameter of a pingear of the second gear cluster is different from a diameter of a pingear of the first gear cluster.
 10. The multiplier sub of claim 8, wherethe first gear cluster includes six pin gears.
 11. The multiplier sub ofclaim 8, further comprising: a mandrel bearing positioned between thethreaded male connector and the mandrel; an upper bearing positionbetween the sleeve and the mandrel and positioned above the first gearcluster; a lower bearing position between the sleeve and the mandrel andpositioned below the second gear cluster; and a lock secured to thesleeve tube interior surface below the lower bearing.
 12. The drill rigof claim 7 wherein the bottom-hole assembly for a drill rig having anabove ground drive motor to form an elongated hole by dislocating solidmaterial of the earth comprises: a drill bit; a drill bit sub connectedto the drill bit; a first multiplier sub; and a second multiplier subconnected between the drill bit sub and the first multiplier sub, wherethe first multiplier sub and the second multiplier sub each comprise: asleeve having a threaded male connector attached to a sleeve tube, wherethe sleeve tube includes an sleeve tube interior surface lined withteeth; a mandrel having a threaded female connector attached to amandrel shaft, where the mandrel shaft is positioned within the sleevetube and includes a mandrel shaft exterior surface lined with teeth; afirst gear cluster having a plurality of first gear cluster pin gearspositioned within the sleeve tube between teeth of the sleeve andmandrel; and a second gear cluster having a plurality of second gearcluster pin gears positioned within the sleeve tube between teeth of thesleeve and mandrel, where the first gear cluster is separated from thesecond gear cluster by an intermediate bearing, and where a teeth ratiobetween the sleeve the mandrel, the first gear cluster, and the secondgear cluster is a value that configures the mandrel to spin at leasttwice as fast as the sleeve.
 13. The bottom-hole assembly of claim 12,where a diameter of a pin gear of the second gear cluster is differentfrom a diameter of a pin gear of the first gear cluster.
 14. Thebottom-hole assembly of claim 12, where the first gear cluster includessix pin gears.
 15. The bottom-hole assembly of claim 12, furthercomprising: a mandrel bearing positioned between the threaded maleconnector and the mandrel; an upper bearing position between the sleeveand the mandrel and positioned above the first gear cluster; a lowerbearing position between the sleeve and the mandrel and positioned belowthe second gear cluster; and a lock secured to the sleeve tube interiorsurface below the lower bearing.
 16. The drill rig of claim 7 whereinthe below ground mechanical system to reduce vibration in a drill rigconnected to a drill pipe, a drill bit, and an above ground drive motorto form an elongated hole in earth by dislocating solid material fromearth comprises: the drill bit; a drill bit sub connected to the drillbit; a first multiplier sub; and a second multiplier sub connectedbetween the drill bit sub and the first multiplier sub, where the firstmultiplier sub and the second multiplier sub each comprise: a sleevehaving a threaded male connector attached to a sleeve tube, where thesleeve tube includes an sleeve tube interior surface lined with teeth; amandrel having a threaded female connector attached to a mandrel shaft,where the mandrel shaft is positioned within the sleeve tube andincludes a mandrel shaft exterior surface lined with teeth; a first gearcluster having a plurality of first gear cluster pin gears positionedwithin the sleeve tube between teeth of the sleeve and mandrel; and asecond gear cluster having a plurality of second gear cluster pin gearspositioned within the sleeve tube between teeth of the sleeve andmandrel, where the first gear cluster is separated from the second gearcluster by an intermediate bearing, and where a teeth ratio between thesleeve the mandrel, the first gear cluster, and the second gear clusteris a value that configures the mandrel to spin at least twice as fast asthe sleeve.
 17. The below ground mechanical system of claim 16, where adiameter of a pin gear of the second gear cluster is different from adiameter of a pin gear of the first gear cluster.
 18. The below groundmechanical system of claim 16, where the first gear cluster includes sixpin gears.
 19. The below ground mechanical system of claim 16, furthercomprising: a mandrel bearing positioned between the threaded maleconnector and the mandrel; an upper bearing position between the sleeveand the mandrel and positioned above the first gear cluster; a lowerbearing position between the sleeve and the mandrel and positioned belowthe second gear cluster; and a lock secured to the sleeve tube interiorsurface below the lower bearing.